The Niobrara and Codell in the Wattenberg Field of the Denver-Julesburg Basin (DJ Basin)have been in the centerstage of horizontal drilling and multi-stage hydraulic fracturing ever since 2007. Based on the current well completion strategy, oil rates drop to 20 bbl/day/well in five years of primary production. The cumulative primary production in the first five years amounts to 3%. Nonetheless, a substantial amount of producible hydrocarbon still remains. In this paper, we propose a most feasible enhanced oil recovery (EOR) technique for the Niobrara and Codell and other similar unconventional oil reservoirs. Realizing the unavailability of CO2 in the area while having easy access to methane, ethane, propane and butane, we designed an injecting gas consisting of ethane enriched with methane, propane and butane for EOR. A dual-porosity compositional model was constructed using data from seismic, well logs, core analysis, and production performance. After successful history matching, as well as verification with seismic and microseismic interpretations, a producer with five years of production history was converted to an EOR-gas injector in the numerical model. We used the model to determine the optimal injection gas composition for producing the largest amount of oil. We also studied the contribution of molecular diffusion at the fracture-matrix interface for the incremental oil recovery from gas injection. Model results indicate that converting three producers to injector wells, and producing from the remaining eight producers, yielded total oil recovery of 4.68% in fifteen years of production with 13% of which attributed to gas injection EOR.
Foam reduces gas mobility and can improve sweep efficiency in an enhanced-oil-recovery process. Previous studies show that foam can be generated in porous media by exceeding a critical velocity or pressure gradient. Such pressure gradients are typically encountered only near a well and therefore, it is uncertain whether foam can propagate far from wells. Theoretical studies show that foam can be generated independent of pressure gradient during flow across an abrupt increase in permeability. In subsurface flow, such sharp permeability changes occur across different length scales. Laminations and cross-laminations, for example, are commonly found small-scale features, whereas unconformities, including layer boundaries and erosional surfaces, are field-scale features that are associated with sharp permeability contrasts across them. In this study, we validate theoretical predictions of foam generation through a variety of experimental evidence. We perform coreflood experiments involving simultaneous injection of gas and surfactant solution at field-like velocities into a model consolidated porous medium made of sintered glass. The core has a well-characterized, sharp permeability transition achieved by sintering glass of different grain sizes. Pressure gradient is measured across several sections of the core to identify foam-generation events and the subsequent propagation of foam. X-ray computerized tomography (CT) provides dynamic images of the coreflood in the form of phase saturations as they develop through the experiment. We investigate the effects of the magnitude of the permeability change and injected gas fractional flow on foam generation and mobilization.
The recovery factor of Eagle Ford shale is estimated around six percent, which means that considerable amount of oil will be left behind after primary production. A major technique to enhance oil production in Eagle Ford could be gas injection since waterflooding is not plausible. This paper presents a novel inhouse multi-component, multi-phase, dual-porosity numerical model including molecular diffusion. This model evaluates ethane-rich gas EOR schemes to recommend on the injection mechanisms and maximize the production performance in support of field design and applications.
There is a great interest to develop an enhanced oil recovery technique for the unconventional shale reservoirs to increase its oil production beyond the primary production. The model, we present, was developed to address this issue while adhering to the thermodynamic complexities of the confined space, which includes crossing the phase boundaries during phase evolution, the wall effects in efficient and computationally robust procedures. It also determines the effect of molecular diffusion on transport mechanisms. The analysis of production data from Eagle Ford wells is used in conjunction with the simulation results to evaluate the increase in recovery after gas injection.
To model the flow for both primary and enhanced recovery, an appropriate model involving advective flow and molecular diffusion is needed since Darcy flow is by no means the dominant flow mechanism considering the average pore throat size measured in Eagle Ford formation. One major requirement for the process is providing adequate residence time to the injected gas for molecular diffusion to take place across the matrix-fracture interface. The simulation results demonstrate that the ethane-rich produced gas injection as an enhanced oil recovery mechanism will improve the production. In particular, an increase of at eleven percent in cumulative oil production is achieved. Furthermore, we present the usefulness of the formulation in analyzing pressure and rate variation with time as well as forecasting future performance of unconventional reservoirs.
In this paper, we present a new compositional diffusivity model which determines the appropriate injection mechanisms using different gas injection scenarios for the field applications in Eagle Ford. Our method provides a better understanding of the physical phenomena of fluid flow processes in unconventional reservoirs which affect the reservoir performance for both primary and enhanced recovery.
O'Brien, W. J. (Nitec LLC) | Moore, R. G. (Schulich School of Engineering, University of Calgary) | Mehta, S. A. (Schulich School of Engineering, University of Calgary) | Ursenbach, M. G. (Schulich School of Engineering, University of Calgary) | Kuhlman, M. I. (MK Tech Solutions)
This paper outlines the results of a comparative study of air- and immiscible CO2 - Water injection based Enhanced Oil Recovery (EOR) processes for a 30+ °API tight, light oil reservoir. This was accomplished by embedding multiple low- permeability core plugs in crushed reservoir core material to create a composite core that was contained in a 1.84 m long core holder. The objectives of this unscaled experimental work were: 1) to understand the suitability of each EOR process for a low permeability reservoir, 2) to define process parameters prior to a potential field pilot, and 3) to understand the relative merits of each EOR process to mobilize light oil from a tight matrix to a fracture network.
A detailed experimental investigation was conducted at realistic reservoir conditions to evaluate the feasibility of an air injection-based EOR process. The air injection results were compared with those from an immiscible CO2-Water injection EOR experiment using the same experimental setup and reservoir conditions. Both the air- and CO2 - Water coreflood tests were performed at 10.3 MPa (1500 psig) and 99 °C in a 100 mm diameter, 1.84 m long composite core-holder using 38 mm diameter reservoir core plugs (that represented the matrix) and mounted within the crushed reservoir core material (that represented the fracture); inert helium gas was used to pressure up the core-holder to reservoir pressure. Permeability of the core plugs was from 0.3 to 3 millidarcies, while the permeability of the crushed core material was 1 to 3 Darcies.
Air injection was performed as a standard combustion tube test with injection of 2.3 pore volumes (PV) of air to burn 71% of the packed core length (including helium, a total of 4.3 PV of gas injected). The CO2-Water coreflood was performed with the injection of 2.86 PV of CO2 followed by an extended soak period, then a second injection of an additional 2.86 PV of CO2, followed by the injection of 2.6 PV of water.
The pre- and post-test core plug measurements of oil saturation show that the air injection process removed significantly larger quantities of hydrocarbons than the immiscible CO2-Water injection process. Relative to the initial conditions of the core plugs for the Air-Injection experiment, 95+ percent of the hydrocarbons were removed; noting that some fraction of original oil was consumed as fuel. In the post-test CO2-Water injection core plugs, oil recovery was in the range of 30 to 55 percent of OOIP. These findings suggest, under an appropriate field design, that both processes have the potential to recover incremental oil from tight reservoirs. However, the air-injection may be better suited to mobilize oil, due to thermal expansion, rather than the CO2 - Waterflood process.
Water alternating gas (WAG) injection is a common technique in enhanced oil recovery. However, gas injection often associates with fingering due to high gas mobility, which leaves a large portion of the reservoir unswept. This study addresses gas mobility control observations through novel X-ray microfocus visualization of core-flood experiments and interpretation aided by numerical simulation. We use foam as our primary mobility control agent for improving conformance.
The experimental setup utilizes an automated fluid injection system monitored by an X-ray microfocus scanner to quantify displacement patterns and saturations during WAG core-flood experiments. The core-flood device – placed within an X-ray shielded cabinet – is wirelessly operated through a computer. The resolution of the images permits observation of not only core scale fingering but also pore-scale displacement. We use a metastable foam with surfactant dissolved in the liquid phase to stabilize the gas diffusion in the liquid and to decrease the permeability and/or lower the apparent gas viscosity.
Results show that saturation patterns and displacement front during WAG injection are highly influenced by bedding orientation and rock heterogeneity. Without gas mobility control during WAG injection, fingering and early breakthrough occur in those cases in which bedding orientation facilitates gas to flow through high permeability layers. In these cases, sweep efficiency is low during early time injection of nitrogen and only improves after injection is prolonged. With gas mobility control, the displacement efficiency is significantly improved. Also, dynamic processes like phase trapping, which could severely impair permeability and overall sweep efficiency, is more clearly visualized with the microfocus technique. Simulation work matches experimental data well and replicates saturation patterns measured experimentally in laminated Berea sandstone samples.
The novel visualization technique presented here provides new pore-scale experimental insight to quantifying WAG displacement in heterogeneous media, a resolution one order of magnitude higher than with medical X-ray CT or other core-scale visualization techniques. The findings are useful for understanding flow regimes in structurally complex and heterogeneous formations.
This work presents the conceptual development and experimental evaluation for a new technique to create blocking foams in matrix rock systems by the injection of the foaming agent dispersed in the hydrocarbon gas stream. This new technique aims at simplifying the operation and reducing costs for the deployment of EOR foams in gas injection based projects, and overcoming the disadvantage of limited reservoir volume of influence obtained in the SAG technique.
A systematic experimental work is implemented to investigate the effect of the dispersed chemical (surfactant) concentration and the gas velocity on the ability to create blocking foams at high pressure and temperature, and using representative consolidated porous medium and fluids coming from the Piedemonte fields in Colombia. The concept behind this new technique is the transfer of chemical foamer from the gas dispersion into the connate or residual waters present in the hydrocarbon reservoirs under exploitation, due mainly to the chemical potential derived from the contrast in chemical concentration between the dispersed phase and the in-situ water.
Results herein confirm that it is possible to create blocking foam by this technique in a consolidated sandstone core at residual oil and water conditions, after being submitted to a gas flooding displacement. This condition is obtained as far as the gas velocity is above a minimum threshold, and the concentration of the active chemical is above certain limit (138 ppm for this case). Successful experiments with foams created by gas dispersed surfactant showed much longer stability periods when compared with results from foams created by the SAG technique at much higher chemical concentration (2,000 ppm). Application of this foams technique was done in a field pilot. About 600 Bbls of foaming solution were dispersed in the hydrocarbon gas stream in one gas injector of a Piedemonte field (Colombia, South America). Gas injectivity in the well was impaired after two weeks of injection, and the oil production well influenced by this injector changed its performance showing incremental oil production and flattening of the gas oil ratio (GOR) shortly after the dispersed chemical injection period. This innovative foams technique could also be extended to other non-condensable gases at field operating conditions like CO2, Nitrogen, Air, and Flue Gas.
Huff and Puff gas injection through horizontal wells in shale petroleum reservoirs is moving cautiously from being a promising theoretical possibility, to becoming a reality for increasing oil recovery. This study investigates how oil recoveries from shales can be increased by (1) a combination of refracturing and huff and puff gas injection, and (2) huff and puff gas injection when the length of the gas injection and production cycles are increased over time.
The possibility of improving oil recoveries from shales by a combination of refracturing and huff and puff gas injection is investigated using a compositional simulation approach. Previous studies published in the literature, have considered the implementation of regular constant-time cycles throughout the huff and puff process. This may not be the optimum strategy. In this work, the use of cycles with increasing time-lengths is investigated with a view to maximize the oil recovery by huff and puff gas injection.
The combination of (1) huff and puff gas injection followed by (2) refracturing and (3) stopping gas injection is found to be a good option to increase oil recovery from shale petroleum reservoirs when the initial hydraulic fracturing (IHF) has been successful. The benefits of this approach are demonstrated through a comparison made when refracturing is carried out without previous huff and puff injection. If the IHF has not been implemented properly, the huff and puff gas injection does not provide attractive recoveries. In this case, a refracturing job followed by huff and puff gas injection is shown to improve recoveries significantly. A comparison of the different scenarios considered in this paper shows that proper design of the injection and production schedule is very important in the development of a huff and puff gas injection. Optimizing the schedule by using the appropriate cycles with variable increasing-time spans can lead to improving the huff and puff performance.
This study investigates how to increase oil recovery from shale petroleum reservoirs by (1) the combined use of refracturing and huff and puff gas injection, and (2) the use of cycles of variable length as opposed to the regular-length constant-time cycles considered in previous publications. To the best of our knowledge, the two cases considered in this paper are novel and have not been published previously in the literature.
Immiscible Water Alternating Gas (IWAG) is an EOR process whereby water and immiscible gas are alternately injected into a reservoir to provide better sweep efficiency and reduce gas channelling from injectors to producer wells, aiming to stabilize the displacement front and increase contact with the unswept areas of the reservoir. In this work, we present a summary of best practices for laboratory evaluation of IWAG. This work was motivated by observations related to the way laboratory measurements are normally done, which could result in erroneous interpretation if the results were to be used directly for the design of a field application.
The set of best practices were collected from own work expanding over two decades of laboratory work, discussion with experts from laboratory services and research centres, and a comprehensive literature review. They were tested in a laboratory workflow and compared to conventional workflows used by most laboratories. The recommended approach covers steps from sample preparation, experimental setup, measurement protocols, guideline for process design, and data QA/QC for later use in reservoir simulation.
Among the best practices, particular attention is given to the type of fluids and samples used for the measurements based on the strong effect of rock-fluid interactions on the IWAG performance. The layout of the experimental setup, and how the injection and displacement process is done and the flow effects quantified. Other best practices relate to the selection of the WAG slug ratio, and required initial conditions of the core where the laboratory testing is done. The number of cycles in the WAG injection affects the recovery. On the initial condition of the sample, the knowledge of the sample wettability at the start of the WAG is critical since the optimum ratio is influenced by the wetting state of the rock. A WAG ratio of 1:1, which is the most popular in field applications, is not necessarily the most appropriate.
Regarding flow properties, relative permeability should be evaluated under three-phase conditions and making sure hysteresis effects are well captured data in general not readily available. Special attention should be given to the selection of correlations for calculating three-phase relative permeability widely reported in the literature; in most cases they are not accurate for WAG injection since they do not consider special treatment of water-gas cycle.
We present a side by side comparison of the impact on the laboratory results will be given on using recommended best practices to more routine laboratory implementations. These best practices, with focus on immiscible WAG, provide a new unique workflow for the execution of laboratory programs supporting a better understanding of the involved phenomena and providing accurate data for immiscible WAG process design.
Jahanbakhsh, A. (Centre for Enhanced Oil Recovery and CO2 Solutions, Institute of Petroleum Engineering, Heriot-Watt University) | Sohrabi, M. (Centre for Enhanced Oil Recovery and CO2 Solutions, Institute of Petroleum Engineering, Heriot-Watt University) | Fatemi, S. M. (Centre for Enhanced Oil Recovery and CO2 Solutions, Institute of Petroleum Engineering, Heriot-Watt University) | Shahverdi, H. (Centre for Enhanced Oil Recovery and CO2 Solutions, Institute of Petroleum Engineering, Heriot-Watt University)
Gas/oil interfacial tension (IFT) is one of the most important parameters that impact the performance of gas injection in an oil reservoir. The choice or design of the composition of the gas injected for EOR is usually affected by the gas/oil IFT. In conventional reservoir simulation, IFT does not explicitly appear in the equations of flow and therefore its effect must be captured by the shape and values of relative permeability curves. A few studies have been previously reported for IFT effect on two-phase flow but very little have been done to investigate gas/oil IFT effect under three-phase flow conditions. The objective of this study is, firstly, to investigate the impact of gas/oil IFT reduction on two- and three-phase relative permeabilities using coreflood experiments. Secondly, to investigate the effect of changing gas/oil IFT value (immiscible and near-miscible) on the performance of WAG injections and residual oil saturation reduction at laboratory scale.
Two- and three-phase (WAG) coreflood experiments have been performed on water-wet and mixed-wet cores at three different gas/oil IFT conditions. These experiments were conducted on Clashach sandstone cores with a permeability of 65 and 1000 mD. The two- and three-phase relative permeabilities were estimated from the results of the coreflood experiments using our in-house software (3RPSim) and were compared with each other on the basis of their gas/oil IFT values. Moreover, the impact of gas/oil IFT reduction on the performance of gas and WAG injection and in particular on the reduction of residual oil saturation was investigated. The results of our studies were also compared with the existing literature on the laboratory investigation of WAG injection.
The results show that in two-phase gas/oil systems, the relative permeability of non-wetting phase is more affected by a reduction in the gas/oil IFT compared of the relative permeability of the wetting phase. Comparing the curvature of the gas and oil relative permeability curves shows that although the curvature decreases by a reduction in gas/oil IFT but it is still far away from straight line even at ultra-low IFT values. In three-phase flow system, reduction of gas/oil IFT affects the relative permeabilities of all the three phases (gas, oil and water).
The results show that at high gas/oil IFT or immiscible WAG injection, the most reduction in residual oil saturation is achieved in the first injection cycle and further WAG cycles do not result in a significant additional reduction in oil saturation. On the contrary, at low gas/oil IFT or near-miscible WAG injection, the residual oil saturation keeps decreasing as the number of WAG cycles increases. Moreover, the reduction in residual oil saturation was more effective when the immiscible WAG experiments started with gas injection (secondary WAG).
Production from tight formation resources leads the growth in U.S. crude oil production. Compared with chemical flooding and water flooding, gas injection is a promising EOR approach in shale reservoirs. A limited number of experimental studies concerning gas flooding in the literature focus on unconventional plays. This study is a laboratory investigation of gas flooding to recover light crude oil from nano-permeable shale reservoirs.
In this work, the N2 flooding process was applied to Eagle Ford core plugs saturated with dead oil. To investigate the effects of flooding time and injection pressure on the recovery factor, two groups of core-flood tests were performed. In group one, flooding time ranged from 1 to 5 days in increments of 1 day; in the other group, the injection pressure ranged from 1,000 psi to 5,000 psi in increments of 1,000 psi. The experimental setup was monitored using X-ray CT that helped to visualize phase flow and estimate the recovery efficiency during the test.
The potential of N2 flooding for improving oil recovery from shale core plugs was examined, and the recovery factor (RF) of each case was presented. The results from group one showed that more oil was produced with a longer flooding time. However, the incremental RF decreased with the increase of flooding time. The oil recovery was significant at the initial period of the recovery process, and a longer flooding time had less effect on extracting more oil. With flooding time constant in 1-day, the results from the second group indicated that RF increased with injection pressure, especially rising pressure, from 1,000 psi to 2,000 psi. The gas breakthrough time became shorter with the increase of injection pressure. The analysis of the CT number showed that the oil recovery process mainly occurred before the gas breakthrough. Once a fluid flow path was established, the injected gas flowed through the limited communication channels; thus, no extra oil could be extracted without increasing the injection pressure. This experimental study illustrates that gas flooding has liquid oil production potential in shale reservoirs.